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Under the uniform parallel well pattern widely used in shale gas cluster well, the directional drilling limits (DDL) can better reflect the productivity of shale gas cluster well than extended-reach limits (ERL). In this paper, the concept of directional drilling limits is proposed to predict the productivity of shale gas cluster well. Around this concept, the forecast model of mechanical directional drilling limits is established by introducing the objective function, geometric constraints, mechanical constraints and operation conditions. A shale gas cluster well developed by Sinopec in Fuling field is analyzed. The mechanical directional drilling limits for different constraints are calculated, and the laws of the directional drilling limits under different operation conditions are analyzed. The results indicate that the cluster well optimized by the established model can drill more horizontal wells than that without optimization. The mechanical directional drilling limits firstly increases and tends to stable with the increases in the holding angles. Besides, running-in is the limit operation in sliding and rotating mode, and high friction coefficient is the fundamental mechanical constraint for directional drilling limits. The constrained optimization model established in this paper can provide a theoretical guidance for shale gas cluster well engineering to improve outputs and avoid drilling hazards.

Environmental impacts due to exploration to the abandonment of oil and gas wells are a major focus when the wells are planned and drilled. However, there is no industry standard to quantify the impact due to complex indicators and associated variables. So, it is necessary to have an assessment framework and a methodology with the help of the digital transformation that provides an integrative index. This index allows a baseline to estimate the benchmarking for the well engineering not only during planning but also in real-time as the well is drilled and produced. This paper presents and validates a new model for the sustainability index for well design and engineering in the life cycle of the well. This proposed method avoids some of the vagueness of well’s sustainability and can be used and applied practically. It is based on various metrics and weightage assigned when a well is planned, designed, and engineered. Evaluating the index for well engineering is based on the following elements: environmental impact, well design and engineering, functionality and optimization impact, impact of well and maintenance costs, health and safety impact, societal impact. Each element contains sub-elements. This process involves individual indexing through backpropagation of neural networks combined with bat algorithm to obtain the final overall index.

With the basic characteristics of conventional horizontal wells, the so-called complex wells including horizontal extended-reach wells, multi-lateral horizontal wells, U-shaped wells, cluster horizontal wells, etc., are advanced well types for the efficient development of low-permeability, unconventional, deep-water, and deep oil and gas reservoirs, which have been highly concerned all over the world. Significant progress at home and abroad has been made in relevant researches and practices and is expected to play an important role in the efficient development of shale oil and gas. To meet the basic needs of environment & safety, land conservation, cost reducing and efficiency improving, it is urgent to create a unique and efficient mode for developing shale gas. Therefore, an efficient shale gas development mode for mountainous areas and an engineering and technical support system are presented based on large cluster horizontal-well engineering. An equation is thus obtained for calculating the maximum number of horizontal wells arranged allowably in “Well Factory” on a single platform. The general research and development of large extended-reach well technology are analyzed by expounding the basic concept of an extended-reach well and its drilling extension limit. And a calculation method is thus established to predict the maximum measured depth of open hole in extended-reach drilling. Moreover, some relevant research results and their significance for downhole tubular mechanics & mechanical extension limits in extended-reach drilling are also briefly introduced in this paper. The conclusions are drawn that, by following the idea of “integration of geology and engineering” in oil and gas development, these research results have a foreseeable application prospect in shale gas development in the mountainous areas in the future, and will contribute to new progress in China's “Shale Revolution”. Keywords: China, Mountainous areas, Shale gas, Efficient development mode, Large cluster horizontal wells, Integration of geology and engineering, Extended-reach drilling, Design and control

In terms of funders, we would like to acknowledge the Pufendorf Institute for Advanced Studies at Lund University as well as the St Andrews Sustainability Institute, School of Geography and Sustainable Development, University of St. Andrews for their financial support in this initiative. With the dual challenges of reducing emissions from fossil fuels and providing access to clean and affordable energy, there is an imperative for a transition to a low carbon energy system. The transition must take into consideration questions of energy justice to ensure that policies, plans and programmes guarantee fair and equitable access to resources and technologies. An energy justice framework is outlined to account for distributional, procedural and recognition inequalities, as well as emerging themes such as cosmopolitan and non-Western understandings of justice, in decision-making relating to energy systems. The spectrum of research offers critical perspectives on the energy transition as well as tools for decision-making and policy processes. Quantitative, qualitative and mixed methods all contribute to our understanding of the problems and the success of responses. The studies presented in this special issue illustrate that the field of energy justice is a rapidly growing arena. There is constant innovation taking place in enabling the transition with new structures, processes and metrics being introduced to guide decision-making and a more holistic view of the community emerging where acceptance, mobilisation and empowerment are opening possibilities for a just transition to a low carbon energy system. The importance of introducing the interdisciplinary approach between social sciences and natural sciences as well engineering implementation supported by scientific data and experiments shall be emphasized in future studies. Postprint

The future of oil and natural gas drilling is dependent on deep well drilling operations. Kick tolerance is a concept which is very important for the industry to ensure that the wells are drilled safely. Especially for natural gas wells one of the most important requirements in deep well engineering design is the kick tolerance calculations. The literature survey reveals that there is no global standard utilized for the kick tolerance calculations by any of the operators, drilling contractors or any other official institutions. It is obvious that the industry needs a reliable procedure for kick tolerance calculations not only for safer drilling but also optimized well plannings. In order to test the methodology a data acquisition process has been implemented to collect the data from the literature. A depth based novel kick tolerance calculation methodology that is based on iteration is introduced in this study, which easily identifies if any kick tolerance troubles are going to be encountered or not. The results indicate that with the introduced kick tolerance methodology the engineering teams can design the wells safely provided that the pore pressure and fracture gradient information belonging to the wells are accurate and available as needful. The study outputs the analysis for the well designers in regards to the depths that a well control incident can occur, which differentiates this research study from others by means of identifying the depth ranges for possible well control incidents. The utilization of the novel kick tolerance calculation approach provides an appropriate planning of drilling operations, safer drilling activities and improved capability of natural resource discoveries.

Several calculation methods have been proposed by the researchers in the past with varying degree of precision. These result in different wellbore position estimation. The survey calculations and positions are used in engineering calculations such as torque and drag, drill ahead prediction, displacement of the string, SAG correction etc. Since the survey calculations are the underpinning starting point for the engineering formulations, considerable errors are introduced in the engineering calculations. Most widely used method in the industry is minimum curvature which assumes a circular arc in an inclined plane and this method is better than some of the previously introduced methods like balanced tangential method, average angle method etc. It has also been seen that, the radius of curvature method is more suitable for a rotary mode of drilling, whereas the minimum curvature method aligns when slide drilling. However, using the minimum curvature method, introduces discontinuity at the survey course intervals. This type of constant curvature model due to discontinuity may result in the omission of some contact forces which will result in the under prediction of the hookload or the stresses in the drillstring components or casing or drillpipe wear calculations. This further results in the discontinuity in the engineering calculations also and will be more pronounced when the wellbore twists and turns. To alleviate this problem, wellbore smoothening is done by using advanced survey methods such as spline, natural arc method, curvature bridging etc. A reliable inclination and directional continuous surveys also enable smooth and continuous wellpath making the problem with the minimum curvature method to vanish. This paper presents the research findings not only on the relationship between the minimum curvature method and engineering calculations but also the inherent problem in the commonly used survey calculation methods. It has been shown that both wellbore curvature as well as the borehole torsion are necessary to relate to the mechanical parameters that are used in the engineering calculations such as bending moment, side force and string position.

Stretching the engineering limit in order to deliver a high pressure, wildcat well, ZT-1, driven by design optimization and allocated resources which resulted in well cost optimization. For a successful delivery of ZT-1 well, three (3) engineering limit focus area has been identified and tackled with proper risk mitigations for well design optimization. ZT-1 well was designed based on prognosed mid case PPFG, with sensitivity to high case PPFG. As per standard practises, exploration well design need to consider a drill kick tolerance scenario of 25bbls in 8-1/2" hole section. However, ZT-1 opted for a reduced drill kick tolerance of 10 bbls in order to drill the wildcat reservoir in one-hole section, by considering well operational point of view. Second focus area with regards to collapse and triaxial safety factor for 7" production liner. According to company casing design standard, full evacuation to atmospheric load case need to be considered for production casing, which failed in ZT-1 well design. Since the probability of the said load case to occur in ZT-1 well is very low due to its clastic nature, team applied risk based design approach by using actual data from manufacturer to enable the usage of said 7" casing. Third focus area linked to the lower hard cement pressure test value. According to company Pressure Containment and Control standard, casing should be tested after the cement is hard, to the lesser of 70% of maximum internal maximum internal yield pressure (MIYP), or FIT or LOT plus 500 psi, or 200bbls influx from max PP for exploration well. Since ZT-1 well is using the standard G-Cement, the limitation is on cement integrity that does not allow hard cement pressure test to meet the three criteria's, hence derogation was raised. The three-focus area was challenged with calculated risks and proper mitigations in place. For first focus area, real time pore pressure prediction, assisted by FPWD were utilized to assess the operational limits. A robust Total Depth (TD) decision tree criteria were developed, based on PPFG uncertainty and drilling was limited up to drill kick tolerance to safeguard the operations. Second focus area enable us to utilize current OCTG resources hence resulted in cost avoidance. The third focus area is to allow fast decision-making during operation in case of the plug does not bump thus will cause hard cement pressure test. These effective decision frameworks were developed without compromising the well and the cement integrity. The three derogations were raised to stretch the design and operational envelope set by company in order to deliver fit for purpose well design without process safety incident. ZT-1 was drilled safely to deliver the well objectives.

Pre-job engineering tasks conducted during the drilling design phase have often been an overlooked aspect regarding time and cost savings. This is a critical phase that directly impacts efficiencies and effectiveness while drilling. This paper highlights the multiple benefits of an engineering solution that automates and triggers advanced engineering computations simultaneously. The objective is to realize time savings and accuracy gains necessary for quick evaluation and resolution of the decision-making processes, while eliminating unintentional oversight on engineering requirements. The approach focuses on a fully customizable application that automates sequences of models/ actions; interpretation and validation of results, based on pre-determined criteria; and reporting functionality. This automated solution uses established workflows and conditions, and user defined calculations to conduct typical pre-drill engineering tasks. To demonstrate the tool's capabilities, two wells were reviewed by multiple engineers of varying experience levels. Each performed the pre-drill engineering tasks assigned based on proposed requirements. The outcome reviews the time taken to deliver validated engineering solutions; accuracy of result validation and ability to track compliance to standards. Results from the evaluation of these three Key Performance Indicators (KPI's) are presented and thoroughly described. The validation conducted revealed significant time efficiency gains when executing pre-engineering tasks and automatically validating each simulation (71% overall time-reduction). The accuracy of results was always guaranteed when using the automated method, with a 100% accuracy for both wells analyzed, compared to an average of 92% from the focus group. This improvement is key to ensure the delivery of flawless well designs, consistently and reliably. Additionally, the described potential for ensured compliance based on standardized rules specific to each organization, allows for repeatability and accountability, enhanced through the use of auditable trails. Automation of processes, workflows and equipment is driving the innovative and creative direction for the industry, but it should also steer toward an increase in reliability, performance and minimization of risk in every step of the well delivery process. This fully customizable engineering tool proved to be a highly efficient approach that allows users to eliminate manual, time consuming tasks while removing the potential for accidental oversight in identifying future issues before drilling begins.

Summary The internet of things has brought better connectivity among devices in various industries including the oil and gas industry. With this improved connectivity comes improved applications, especially in the area of real-time data processing and analytics. A major requirement for real-time application is minimized latency. Cloud computing, despite its many benefits, is often limited in that area. A lag often starts and worsens when the realtime data has to go back and forth between field locations and data centers. On the other hand, edge computing enables faster processing speeds. Edge computing applied to real-time well engineering is presented and discussed. It has the potential to be an adequate approach for applications dependent on real-time processing such as geosteering, which requires instantaneous processing to drastically enhance the economic profitability of a well. With edge computing, some sensor data can be cleaned and processed instantaneously to automatically identify the rig state, which is a key step in the real-time well engineering workflow during drilling.

Summary Modern well engineers struggle with digital confusion; they have either too much data or not enough, and the quality is often questionable. Additionally, well engineers are usually operations focused and might not fully appreciate optimization through data-driven insight. This paper illustrates how to optimize the rate of penetration (ROP) in any given field using an automated and timesaving process for designing wells using machine-learning (ML) techniques. By prescribing optimized ROPs through automated ML of offset well attributes, free from subjective human bias, engineers can push technical limits. Automated analysis, regression, and visualization of high-volume data can reduce planning time significantly and help establish optimized operational parameters to reduce drilling time and costs. The next step is to build a real-time downhole advisory system to help achieve the predicted ROPs by predicting and prescribing drilling parameters ahead of the bit.

Technology Update Considering the significant weight of drilling costs in upstream ventures, saving even a few hours of drilling could lead to substantial cost savings on the overall capital expenditures (Capex). Thanks to the big data revolution, cost optimization still has strong potential in drilling operations. Traditionally, drilling performance has been addressed through the analysis of drilling reports written once a day by the operator’s staff. However, high-frequency data are already collected continuously by surface and downhole sensors to address operational safety and continuity. These data contain a huge amount of valuable information that can be used for drilling operations performance analysis (Fig. 1). High-frequency data analysis allows a new level of performance monitoring through the identification of potential invisible lost time and the anticipation of well problems that could be minimized to reduce drilling costs. Data Valorization, Combination More than 60 sensors record high-frequency data during drilling, creating sets of millions of data for a single well. These data can be reprocessed through a set of algorithms to identify each single activity with the highest possible level of accuracy and granularity. As an example, reaming is based on the following seven surface logging parameters: bit depth, well depth, rate of penetration (ROP), weight on bit (WOB), torque, mud flow-in, and standpipe pressure. However not all activities can be automatically detected through surface log-data interpretation. It they cannot be, daily reporting becomes a relevant source of information. Thus, a set of preeminence rules is applied so that the most relevant data can be used and combined as needed at any time to build a complete and precise time breakdown for the analysis of drilling and flat time. This innovative approach is the basis of the Integrated Drilling Data Discovery (ID3) system, developed by kwantis. ID3 manages one single big-data platform to integrate surface logging data with reporting information (e.g., daily drilling reports and bit reports) and measures lithology, trajectories, and other key data while drilling to create a complete set of drilling performance analyses. The system is able to break down the drilling sequence to the most detailed activities (e.g., bit on bottom, reaming, circulating, or on slip) with a 5-seconds accuracy. The information regarding phases, troubles, and equipment are provided by the daily reporting and plotted on the common time or depth bases to create meaningful analytics on a single well or group of offset wells. The applications of these analyses are multiple and provide new capabilities at any stage of the well life cycle: planning, operating, or post-well analysis.

Roller cone bit is one of the main rock-breaking tools in oil and gas well engineering, and its performance could directly affect well drilling speed and cost. The particular structure of roller cone bit and the random breakage in heterogeneity rock make it difficult to study the problem of rock-breaking mechanism of roller cone bit under bottom-hole condition. Although, research on this topic has been carried out and drilling speed models under down hole conditions have been proposed. The research was based on rock intrusion theory and included the condition of bottom-hole pressure. Theoretical analysis shows that during the transient process of strata changing from soft form and medium-hard form to hard form, the drilling rate model is able to explain the influence of various ways of rock breakage on the drilling rate or the rate of penetration (ROP) of roller cone bit. The test results also show that the invasion depth of conical insert and chisel teeth both decreases exponentially with the increase in bit angle and fluid column pressure, where conical insert has greater decreasing rate than chisel teeth. In addition, the present study demonstrates that the intrusive coefficient is essential to quantify the intrusive-resistance capacity of bottom-hole rock.

The Niger Delta is a prolific oil and gas province with almost 160 oilfields and 1,500 wells put on production since the 1960s. Many of these wells have been producing for decades and now find themselves in hands of new operating companies of limited resources. There are strong commercial drivers to keep these wells in production through rapidly planned workover operations. The historical records for these wells are poor and in many instances nonexistent, often being no more than a very simplistic A4 completion diagram lacking in details and summary. The basis for design and the history of numerous interventions has long been lost and the focus of new operators is often on only the production casing and the tubing strings. However, it is imperative to consider the full well architecture and construction history because some were design optimized with minimal casing setting 13 3/8" shallow and completing in 9 5/8". Worst case consequence of this design approach is well blowout and cratering if the production casing fails with a gas column to surface. A generic case is presented to emphasize the reality of this risk. The risks of extending well life, compounded by change of use in late life are discussed in the context of design validation. The causes and challenge of poor well engineering data are reviewed, to establish the historical norms in not only the Niger Delta but globally. The importance of tracking down data in the well Intervention planning process is emphasized. It is further proposed that controlled, as-built drawings of all wells, which do not omit casing details, lithology, and critical component features such as wellheads casing hanger seals and Xmas tree should be electronically created, cloud stored and used as a basis for well bore integrity analysis prior to undertaking interventions/workovers. An example from a North Sea Development Project is presented. Such a system should also be used to establish which critical barriers exist during the intervention, how they will be validated, and how is evidence captured in order to address the typical human factors which are fundamental in many blowouts. Critically the system should produce accurate well integrity reports during operations to track compliance with the plan. A generic example for a typical Niger delta dual bore completion well is presented.

Master's thesis in Petroleum engineering Working stress design is the most common design method used on the Norwegian continental shelf and its simplicity makes it easy to understand. However, other methods as the reliability based design gives a different view on the casing design and gets more attractive as the wells that are being drilled are getting more complex. Reliability based design gives the opportunity to quantify the risk of the design and one of the outputs from this method is the probability of failure. This means that we get a number on how safe our design is and that makes it possible to do a risk assessment as well. Even though reliability based design is a more complex method and need more input data, compared to the working stress design, the results from the simulations are noticeable. A casing grade selection was performed for a 13 3/8” intermediate section based on WSD and then on RBD. The loads considered are burst and collapse. A comparison between the different burst models showed that the API model and the Klever-Stewart rupture limit model had the same spread of data and the API ad-hoc had the largest spread out of the models considered. Since the burst simulation take the rupture limits into account, the Klever-Stewart model was chosen as it seemed to be a the more suitable model for our purposes. Klever-Stewart is also the recommended rupture limit model according to API 5C3 as well. RBD was performed with the use of Monte Carlo simulations in MATLAB. The simulations showed that RBD4 and RBD5, with Klever-Stewart rupture limit as the strength model, that a casing grade equal to N80 and K55 was sufficient to meet our requirements for a high consequence failure. On the other hand, WSD showed that a grade equal to P110 was necessary when considering the safety factor requirements from NORSOK D-010. As for the collapse simulation, the API model was used as the strength model. RBD4 and RBD5 showed that K55 was sufficient to meet our target probability both for a low and high consequence failure. However the WSD showed that a grade equal to L80 was necessary to meet the NORSOK requirements regarding the safety factor. The overall result was that the RBD method gave the opportunity to choose a lower casing grade than the WSD. However, the RBD method is more complex and needs more input data. As RBD is based on the stochastic nature of the variables, distribution for each variable was taken into account. Parameters as mean and standard deviation for different input parameters like e.g. OD, thickness, yield and model error were found in the API 5C3, however some assumptions were made when data was not available. As for the load calculations, the worst case scenario was considered for the RBD4 and WSD, however subjective assumption was added for the RBD5. The overall conclusion is that RBD4 allows you to choose a lower casing grade than WSD. RBD5 gives is less conservative than RBD4 and gives an even lower grade, however more relaxed assumptions were made for RBD5 where the uncertainty in the load was included.

Engineers communicate multimodally using written and visual communication, but there is not much theorizing on why they do so and how. This essay, therefore, examines why engineers communicate multimodally, what, in the context of representing engineering realities, are the strengths and weaknesses of written and visual communication, and how, based on an understanding of these strengths and weaknesses, one can consider using the strengths of each form of communication to address weaknesses in the other. Doing so can possibly enable one to demonstrate for engineering majors how they can, with greater effectiveness, communicate multimodally for representing well engineering realities.

This paper describes the method and results of a probabilistic risk analysis that was used to provide a quantitative basis for a complex and high-stakes design decision for a subsea oil project. Geologic properties were specified as probability density functions based on information from a small number of exploration and appraisal wells. The geological information was coupled to a wellbore fluid dynamics model to simulate operational outcomes for potential well kill operations. Conventional probabilistic sampling and a more efficient experimental design approach were both employed. The key results are cumulative density functions for critical bases of design that are used for risk analysis and final equipment selection. The analysis reinforces the importance of interdisciplinary collaboration, in this case the subsurface disciplines and well engineering, to achieve efficient risk-based designs.

Corporations have to consider the demands emerging in the market in order to catch up with the rapid developments in the business world. In this regard the most discussed topic is the content of management concept. Engineering management as well brings in new dimensions to this discussion. The Engineering management masters programs were designed to meet the growing need in this field. The primary target groups of these programs are engineering students as well engineering personnel. The programs are offered in different forms with respect to thesis; with theses or without thesis, distance or traditional learning etc. In this study, the engineering management master's program at Sakarya University will be investigated with a comparison between distance and traditional education.

Conventional drilling methods have been plagued with huge operational and financial challenges, such as cost of purchasing, inspecting, handling, transporting the drill equipment and most importantly, tripping in-and-out of the drill string whenever the Bottom Hole Assembly (BHA) needs a replacement, needs of wiper trip or when total depth is reached. The tripping in-and-out of the drill string not only contributes to Non Productive Time (NPT) but also leads to well control difficulties including wellbore instability and lost circulation. All this has led Oil and Gas industry, as well as any other engineering industry, to seek for new ways and methods in order to reduce these problems. Thanks to the advances in technical solutions and constant improvements of conventional drilling methods, a new drilling method - casing while drilling has been developed. Casing Drilling encompasses the process of simultaneously drilling and casing a well, using the active casing and thus optimizes the production. This paper presents a review of casing while drilling method (CwD) and its practical usage in drilling wells. The comparison of conventional drilling method and casing while drilling is also presented. The CwD method achieves significantly better results than conventional drilling method.

The design process of a casing program involves the selection of setting depths, casing sizes and grades of steel that will lead to a safe drilling and completion of a well to withstand all encountered loads during the life of the well. The selection of casing setting depth is a very important task in preparing the well plan. Many aspects, such as lithology, over pressured formations, shallow gases, lost circulation and troublesome zones, directional well profiles and regulations must be considered in this selection. The development of new materials (i.e. expandables) and new technologies (casing drilling) as well as future concept like monobore well technology has created the need of new casing shoe calculation methodologies. The proposed concept to dynamically estimate the casing shoe depth while drilling is based on real time data and intensive geo-modeling pre-processing. The concept will start on paper with the classical casing shoe setting depth estimation which is used to identify the critical zones after which the dynamic model is applied and simulated. If positive simulation results are obtained, then the drilling process can be started. The new model can predict while drilling the position of the next casing shoe, taking into consideration measurements while drilling like pore pressure or formation properties. However, the success of this concept is strongly linked to modern or future technologies of monobore.

Thermal recovery is a common and effective method for producing heavy oil. Casing failure is a serious problem in thermal recovery wells. In view of this problem, it is proposed the technique of casing cementing with internal pre-expansion for thermal recovery well. It refers to exert inner pressure on payzone production casing or heat payzone production casing to a certain temperature and make payzone production casing expand in cement solidifying period. We developed simulating experiment table according to field practice and pre-expansion cementing theory. It can simulate cementing technology with conventional, half warm-up and internal pre-pressurization cementing technology, also include steam injection and production process. The technique will be an important foundation for the following field tests and its application.

With the progress of science and technology, human beings explore the energy underground with thousands of meters. As a thermophysical parameter, initial formation temperature (IFT) plays an essential role in deep well engineering. However, it is not easy to predict the IFT accurately before drilling. This work uses a new method to analyze the effect factors of the underground temperature field, and assumes an artificial surface to eliminate the disturbance of the human errors and equipment errors on the surface temperature and thermal conductivity. Considering different distributions of the formation thermal conductivity and the rock radiogenic heat production, an optimized model was established. With this model, the paper predicted the bottom temperature of the main hole of the Chinese Continental Scientific Drilling (CCSD) as 132.80 °C at 4 725 m depth with 0.5% error. When the thermal conduction is dominant in the formation, this simple method can predict the IFT distribution effectively for deep well in the exploration stage. However, it is almost impossible to avoid aquifers in the formation of drilling deep well, an existing drillhole including groundwater is needed to predict for testing the model’s accuracy.

The importance of improving the drilling performance in an E&P company cannot be under estimated as it directly impacts the overall cost of the project. The objective of drilling and well engineering management system is to address the technical and organizational aspects of Drilling operations and deliver the wells in safe and cost effective manner. The different tools that are the vital part of the Drilling and well engineering management system include gates review process for well delivery; section-wise after action review, lesson learned tracking system and non-productive time(NPT) tracking system for continuous improvement from the previous wells. Tools for knowledge and data management and analysis (including technical limits& field specific KPIs) and their input for the upcoming wells is also the part of the system. A cross deliberation, peer review process and auditing system is in place in the process for the compliance check. Notable impacts of the Drilling well engineering management system include rigorous well examination during the gates review process, enhanced risk assessments of various aspects of well planning. The system provides accurate and detailed monitoring of the drilling operations through various tools during the execution phase. Within one year of its implementation, the operator was able to improve the drilling performance by achieving huge benchmarks in exploratory and development prospects across the entire operated blocks. In some of the fields, where the drilling activity is progress for more than 50 years; the implementation of the management system provided around 100 to 150 % decrease in drilling time and cost in the benchmark wells. This paper includes the results from one of the major challenging fields; Adhi field in which subject changes were implemented successfully. This paper provides an overview of the management system, its implementation in the organization and outcomes and benefits achieved in the drilling efficiency through the system.

Master's thesis in Petroleum engineering Mud left static in a well over a longer period of time can begin to gel up or form filter cakes along the formation wall and in washout zones, which can be difficult to remove. Therefore, proper mud mobilization and removal is necessary to ensure a good zonal isolation prior to primary cementing. The Bingham plastic rheology model is widely used by mud engineers to mathematically describe the rheological behavior of drilling fluids. The equation for circulation efficiency is directly related to the fluid velocity profile equations. Relevant theory is introduced before experimentation and results are presented. The experimental work in this thesis is based on a field size mud conditioning operation. The annular geometry between a 95/8-in casing and a 121/4-in borehole is scaled down to laboratory size and configured as a slot for experimental purposes. Accompanying mud rheology and conditioning pump rate is scaled down by the Bingham number similarity method. Particle image velocimetry (PIV) experiments were conducted on an acrylic flow channel for a Newtonian fluid to study the velocity profile. An aspect ratio of 1:10 was found to be acceptable to neglect the sidewall effects when measuring the velocity profile 8,5 centimeters from the wall, both from theoretical solutions and by comparing with experimental results. Carbopol dispersed in an aqueous solution was found to be the most promising yield stress fluid for the future non-Newtonian PIV experiments. Despite being described better by the Herschel-Bulkley rheology model rather than the Bingham plastic model, its rheology was found to be acceptable by comparing the velocity profiles generated by the regression parameters by the two rheology models Both analytical solutions and MATLAB were used to verify the aspect ratio and feasibility of moving on with Carbopol.

Master's thesis in Petroleum engineering The oil and gas industry working on the Norwegian continental shelf have the past years increased the focus on decommissioning of fields, after several years with attention to increase and enhance oil recovery. The topic plug and abandonment has been well-recognized by the Norwegian authorities, the oil and gas industry and the public media due to the expected cost which will affect both Norwegian taxpayers, licence partners and operators working on the shelf. There has been a large emphasis to cut these cost, where companies are currently developing new solutions to enhance the process to plug and abandon wells. The concept “rig-less” P&A have been expressed as a futuristic goal from “Norwegian Oil and Gas” in their roadmap for new P&A technologies [1]. This thesis investigates performance differences of a purpose-built P&A unit based on previous performed well abandonments with regular jack-up rigs. The unit is designed to be a cost-efficient rig alternative to regular jack-up rigs, which is designed to perform heavier well operations, such as drilling. The study focus on P&A operations of offshore platform wells, and includes estimates of cost differences between the chosen concept and a standard jack-up rig. Variables like tripping speed, pumping capacities, tubing retrieval efficiency and durations to mobilize equipment will determine the performance of the unit. A lot of the time spent during a P&A operation is related to tripping of pipe. Wireline and coiled tubing are equipment that reduce tripping time, but will the relationship between cost and performance improvements be satisfactory? The findings of the study indicate that employment of the chosen rig design concept provides better economics in the specific well abandonments used for the comparison. There are several factors which determines if the combination of coiled tubing and wireline yet are the preferred solution. With the “Norwegian Oil and Gas” ambitions to develop more technology to increase rig-less P&A scope, this combination may be the preferred solution, to cope with the future needs.

Wells equipped with flow control devices are a proven method of improving sweep efficiency by controlling the influx of fluids into the well by the addition of a flow restriction at each completion joint. Autonomous Flow Control Device (AFCD) technology has recently achieved the milestone of being approved for full field, commercial application to reduce (1) gas influx in light oil reservoirs and (2) water production in heavy oil reservoirs. Autonomous Flow Control Completions (AFCC) are frequently designed using steady-state well production simulators. The more realistic approach of using a dynamic, reservoir simulator often reduces the exaggerated, single well, production improvement by allowing the reservoir's flow dynamics to be understood in the context of the total field recovery and reservoir's uncertainty. The modelling of AFCCs, as currently implemented in reservoir simulators, is in an early stage of development and requires further improvement. AFCC modelling options in a dynamic, reservoir simulator are discussed in this paper. New workflows for AFCC single-phase performance parametrization with a more reliable, physically realistic model of their performance are presented. It is shown how reservoir simulation of an Advanced Well Completion (AWC) containing ICDs and AICDs can be used to evaluate the control of water production in a heavy oil field. The performance of multiple AWC designs is compared for a range of reservoir simulation models that illustrate various production challenges. New comparison methods are introduced that provide a fundamental understanding of their differences. An oil/water flow modelling workflow for reservoir and well engineering studies for the selection of the optimal (A)FCD completion is provided. Our finding aid engineers to reliably model, and evaluate the “added value”, of AFCC technology on a case-by-case basis.

Master's thesis in Petroleum engineering In the pursuit of more oil and gas to meet the growing demand and replace the declining production, the offshore industry is pushed to invest, explore and drill new wells in deeper waters with harsh environments and with a possibility of HPHT wells and sour well flows. Drilling risers with strength and corrosion resistance capable of handling these extreme conditions are accordingly required. As the water depth increases, the length and weight of the riser might lead to problems in terms of; increased loadings on the handling equipment and tensioner system, as well as storage and transportation limitations. Today, the conventional riser material is steel. Steel is a strong and relatively cheap material. However, it is heavy and not very corrosion resistant. Hence, the industry has turned its focus to lighter alternative materials. Aluminum and titanium risers with their light weight, high strength-to-weight ratio and good corrosion resistance are potential candidates to substitute the heavy steel risers. In order to assess aluminum and titanium as alternative materials in riser design and determine if they are suitable for operations in the harsh environment in the Norwegian Sea, simulation studies in OrcaFlex has been conducted. The environmental data used in the simulations are from the Aasta Hansteen gas field, in an area of the Norwegian Sea where the water depth is about 1200 m. The output from the simulation software are compared with the ISO standard 13624 to find the maximum flex joint angles and von Mises stress. The results from the dynamic simulations show that wave height and drilling fluid density influences the effective tension, flex joint angles and the von Mises stress. The applied top tension proves to have the biggest impact on the results, and should be closely considered during the design phase. Aluminum and titanium both proves to fulfill the given design parameters, and can potentially be an alternative to the conventional steel riser in drilling operations in the Norwegian Sea. However, long term properties such as fatigue and corrosion should be investigated to get the full understanding.

Master's thesis in Petroleum engineering This master thesis investigates the potential of using heat pipes as geothermal heating systems for domestic purposes. The total electric energy consumption in Norway used for heating purposes is estimated to be as much as 100 TWh a year. This means that successful implementation of a new energy system would not only save money for the consumer, but also provide relief to the existing power grids. To examine the possibility of using heat pipes, a case study is performed based on available models and theory adapted for a Norwegian environment. The system is considered as an array of thermal resistances which control how much heat that is possible to extract from the ground. The energy that is extracted represents a cashflow which makes it possible to investigate the profitability of the system designed in the case. The case study shows that when drilling an 800 meter well, 86 250 kWh of heat is possible to extract when utilizing a heat pipe system with ammonia as working fluid. The system can supply 4 houses with heat equivalent to what average households use in terms of electric heating. The economic analysis of the system shows that the system is profitable with a net present value of 331 077 NOK. The minimum depth for this system to show profitability is found to be at approximately 300 meters depth. Though the base case shows profitability, projects like this are highly sensitive to costs related to drilling and selection of materials. The models that are applied do not take into consideration important issues regarding heat pipe operations which add uncertainty to the production numbers. The projects are therefore likely to be economically marginal without any governmental support. The findings in this thesis are still interesting enough to investigate further and develop better models to better understand the working potential of heat pipes as geothermal energy extractors.

Master's thesis in Petroleum engineering It is a well-known fact that wells are increasingly becoming extremely expensive and difficult to drill as well as develop due to increasing water depth, temperatures, and pressures. All these result in an increasing load that subsurface structures must bear. This has resulted in the advent of better equipment and technology to give a cost effective and safety assured project. The birth of better techniques and ideas to cheaply and safely drill wells is still ongoing. This ongoing quest can affect any area of the petroleum industry. This thesis is one of such and is aimed at improving casing design for Well integrity assurance. This work presents the application of reliability based method in casing design/selection, relative to the traditional approach known as working stress design (WSD), which is mainly used and have its setbacks. Firstly, the conventional casing design method is discussed. The traditional working stress design depends on the load and strength of a tubular to generate a safety margin used for design. In essence, the expected loads are kept way below the strength in order to avoid failure. This failure could have a low probability of occurrence but a severe consequence if it does occur or vice versa. The issues with the traditional approach are that it promotes overdesign and is too rigid. Also, the associated risk to the design is rarely quantified giving a non-risk consistent design. In fact, in a situation where the scenario causing failure does not occur, changes cannot be made. In other words, it does not properly account for uncertainties present during a casing design. For instance, it is challenging to obtain acceptable design factor using WSD for deepwater, HPHT wells with high magnitude load. On the other hand, the reliability based approach (RBD) measures the uncertainties and risk of failure of the design. The objective of this study is to demonstrate how to perform the RBD method in casing design. The RBD method was implemented by developing probability distributions for load and strength using limit state equations such as the burst load equations, the hydrostatic pressure equations, and the Barlow’s yield strength equations. This study evaluated and compared the two casing design approaches to determine the best in terms of quantifying the uncertainties and risk in the design. A burst scenario due to kick was developed to demonstrate this method. Furthermore, a model for the load and different models for the strength were considered. Monte Carlo simulations were performed using Matlab and the codes developed can be found in the Appendix. The methodology can be used to predict the probability of failure, analyze risks and perform a sensitivity analysis. One challenge with this approach is that it takes some time to get familiar with the documentation of the methodology. Another issue is that it is difficult to know what input parameters to use for the uncertain input distributions.

The “plan for educating and training outstanding engineers (PETOE)” implemented by the ministry of education and other relevant departments jointly to help engineering higher education cultivate talents that meet the enterprises’ needs and to improve engineering education talent training quality has an important guiding role. Teaching practices show that the proposed preliminary solution would make the student to complete well engineering designs that conform to the common standards and industry goal in future and it will strengthen the cultivation of engineering ability and innovation ability.

Through a tightly integrated collaboration between an operator and a service company, the world's northernmost horizontal well was successfully drilled and tested. Set in the Barents Sea at 73° latitude 350km from Hammerfest, this project de-risked a future commercial field development plan for the Wisting field, which holds some of the largest known oil reserves in the Barents Hoop Area. All three major well objectives were achieved: (1) proving drillability by landing the horizontal well approximately 250m from the seabed (a record for subsea wells) and geosteering for 1400m across several fault blocks, (2) performing a well test within a long interval of reservoir exposure (over 460m) to prove the added productivity of horizontals, (3) acquiring appraisal information: reservoir data in new blocks, estimated oil / water contact (OWC), geomechanical properties, etc. This well was outside the envelope achieved before, and such an extended reach drilling (ERD) operation required a customized well engineering approach at every step. In addition, the hole design was adopted to cater for the drillstem test (DST) string. Different casing designs, string designs and operating parameters were screened in dedicated studies, looking at equivalent circulating density (ECD), torque and drag, hole cleaning, prior experience and contingencies. A combined 3D subsurface, pressure and stress model was built, calibrated to drilling observations, core data and leak off tests and then used as input for subsequent studies (mud window, rock strength for drill ability). The geometry required a constant 9°/30m dogleg from kickoff (no tangent section) to land at reservoir depth. Any interval where that performance was not achieved would have resulted in overshooting the reservoir (too deep). An oil-based mud design was adopted for several reasons, and a dedicated lost circulation material (LCM) strategy established to manage potential losses in the reservoir matrix, in fractures or faults. Important planning and operational considerations were given to safety and logistics, and no issues resulted in this remote and environmentally sensitive area. The mud motor strategy selected after careful engineering simulations landed the well at the reservoir depth, before geosteering near-horizontally for the required 1400m. The partnership has gained invaluable information about the drill ability of such wells in Wisting. Several fault blocks could be accessed with a long horizontal, giving a positive impact on the field economics.

Master's thesis in Petroleum engineering Dynamic aspects of liquid-particle flow were investigated through frequency analysis of pressure gradients and image processing of particle flow patterns. Experiments were conducted in a medium-scale flow loop with a horizontal and an inclined test section. The inclined section contained a drill string, capable of rotating, to simulate annular flow. Experiments were run on single-phase liquid and two-phase liquid-particle flow. The liquid used in the experiments was water and the particles were glass pellets. The pressure gradients for both test sections were recorded at different superficial liquid velocities for both single and two-phase flows. In addition to the pressure gradient, images of the liquid-particle flow were recorded, using high-speed cameras. The pressure gradients were converted from the time domain into the frequency domain, by applying Fast Fourier Transform on the time series of the data. An algorithm was developed to post-process the images and was written as a graphical user interface (GUI) in Matlab. The GUI was able to calculate the dune front velocity, the particle concentration in the static and moving layer as well as the changes in the bed height. The GUI was only applicable to the horizontal section, as the drill string in the inclined section caused problems with the processing. The dune front velocity calculated from a cross-correlation of the images matched up well with the amplitude peaks in the frequency spectrum.

Master's thesis in Petroleum engineering On the Norwegian Continental Shelf (NCS) today, there are 1033 subsea wells that are classified with the status online/operational, Drilling, Predrilled, Suspended and Closed[1] and these subsea wells will have to be permanently plugged and abandoned (PP&A) at some point. When the revenue of these subsea wells decreases and the cost is the driving factor, we are left with two options; permanently plug the reservoir section and reuse the slot by drilling a sidetrack or PP&A the subsea well. P&A operations is associated with high cost for the operating companies, licensees and the Norwegian taxpayers. To maintain the production on the NCS, one have to drill new wells to ensure new discoveries. However, as new wells are drilled others have to be PP&A. By using a riserless light well intervention (RLWI) vessel to conduct P&A operations, one can exclude the use of expensive mobile offshore drilling units (MODUs) and consequently maintain the drilling activity on the NCS. The current practice is to use a semi-submersible rig with marine riser to perform the res-ervoir – and intermediate abandonment. By utilizing the current practice and convert it to the new concept of conducting PP&A from a RLWI vessel, we could find the technology gap and the best suited subsea well candidates. The intention is to perform full riserless P&A operations using wireline, coiled tubing and main winch (i.e. a rig-less approach) combined with additional equipment. A large proportion of the current and future subsea wells on the NCS and in the rest of the world will be potential candidates for riserless PP&A with a RLWI vessel. Riserless P&A operations of subsea wells with low well abandonment complexity will most likely reduce the overall P&A expenditures because RLWI vessels has a lower day rate and an effective method of performing the P&A operation. The objective of this thesis is to identify the RLWI vessel’s potential to perform full riserless P&A operations and present its operational boundaries with respect to well abandonment complexity. A description of available and required technology is also given. Three individual base cases with increasing complexity containing operational sequences and well barrier schematics will be presented to show application of existing and required technology and to identify the main challenges.

Old platforms are not well known for extended-reach drilling (ERD) operations mainly due to rig and hydraulics limitations. ERD wells demand robust rig capabilities, good hydraulics systems, and equipment reliability. In addition, the well profile, rotary steerable system (RSS), measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools, surveying, and new technologies are extremely important to the success in drilling an ERD well. RSS and drillpipe selection are important factors for hydraulics optimization. Surveying techniques are also important for time saving and improved efficiency. An ERD well in the North Sea Statfjord field was kicked off in the 17 ½” section from the openhole cement plug through a 50m window between the 20” casing shoe and 13 3/8” casing stump, ensuring a smooth well profile and reduced doglegs compared to the whipstock window exit. The 17 ½” section was drilled and landed at a 79° inclination using point-the-bit RSS technology, and the 12 ¼” section was drilled in two runs as planned using the point-the-bit RSS withstanding more than 550 hours down hole. The 9 5/8” liner was run and floated successfully in the ~6000-m section. Strict adherence to surveying techniques and quality control processes proved very helpful to meet Operator technical requirements. The 8 ½” section was drilled and landed on top of the reservoir with an inclination decrease from 88° to 35°. New MWD technology was successfully used in drilling the 6” section. These latest technologies as well as employing appropriate techniques help to drill ERD wells on aged platforms like those in the Statfjord field. Copyrights 2017, Society of Petroleum Engineers. Reproduced with permission of SPE. Further reproduction prohibited without permission [1].

Master's thesis in Petroleum engineering Ensuring precise estimation of temperature is a critical process for well planning and real-time drilling operations, especially for Extended Reach Drilling (ERD). Therefore, a temperature model has been developed to predict accurate wellbore temperature distributions for ERD applications. The model offers improvements to existing circulating temperature models in terms of more realistic drilling fluid properties and by introducing effects of heat sources that occurs in a drilling operation. In this work, temperature dependent drilling fluid transport and thermal properties are considered to improve the accuracy of the temperature model. Experiments have been performed to determine the behavior of drilling fluid density and viscosity under high pressure and high temperature conditions. Measurements of viscosity allows the effect of non-Newtonian behavior to be included in the convective heat transfer processes. Furthermore, applying a non-Newtonian pressure loss model enables an opportunity to incorporate the impact of non-Newtonian behavior on the wellbore pressure distribution and thus pressure dependent drilling fluid properties. Another important aspect of the approach in this work, is the introduction of heat source terms. Heat generation that occurs during drilling processes have the potential to affect the wellbore temperature distribution. To give a better estimation of wellbore heat transfer processes, heat generation due to drill pipe rotation, drill bit friction, frictional pressure losses, and the Joule-Thomson coefficient is considered. Results from a sensitivity analysis indicate that parameters related to the hydraulics of a wellbore system have a significant effect on the temperature distribution. The flow rate is found to be a major contributor. Drilling fluid viscosity, density, and specific heat capacity have also shown significant effect on the temperature distribution. On the other hand, mechanical processes and heat generation due to friction are found to be less dominant. Results verify that the approach in this thesis provides an accurate wellbore temperature distribution with the possibility to enhance drilling performance and optimize well design.

Master's thesis in Petroleum engineering The basis of this thesis is an attempt to design, construct, and implement a fully autonomous lab scale drilling rig with real time optimization and capable of drilling detection and subsequent mitigation. Two simplified drill-string models are applied to be used in ROP models for drilling optimization. Several drilling problems pertinent to a small-scale rig are discussed with solutions to identify and mitigation procedures are proposed. This thesis also goes in to the necessity control system and data acquisition tools, such as filtering, system coordination, human machine interface (HMI), etc.… required to create a real-time lab scale autonomous rig.

Electronic systems are constructed through hierarchical design layers such as well engineering, memories, latches, flip-flops (FFs), combinational logics, processors, operating system (OS), middleware, firmware and, applications. A number of mitigation techniques have been developed in each design layer. Typical mitigation techniques in each layer and their limitations are introduced and discussed. Integration of them for achieving hyper mitigation strategies are also discussed in this chapter with some challenging features.

Exploration for deep-geothermal resources is still a costly and high risk operation. The research association “Geothermal Energy and High Performance Drilling Research Program, gebo” was founded to improve the cost effectiveness of geothermal energy production in particular by developing new drilling concepts for deep geological layers. A mono-diameter borehole casing concept is developed to achieve this ambitious aim. To accomplish this, a special type of casing is essential, structured from folded tubulars for expandable casing applications featuring clover-like cross sections and expandable to a cylindrical form when the casing is at its downhole position. A smaller borehole volume and a reduction of drilling time and casing related costs are the main advantages of this method compared to conventional drilling. Design, material selection and realization of the folded tubulars take place at the Institut fur Werkstoffkunde (Materials Science). The evaluations of the results are based on residual stress analysis and the measurement of the geometry after each deformation step at the Institute of Production Engineering and Machine Tools (IFW).

To improve the system efficiency of rod pumped wells is a systematical engineering which depends on various cost control methods during the operational process and technologies of improving equipment & system operational efficiency, and closely related to pumping equipment selection, production parameters optimization design and well management. This paper analyzes the existing problems under current management mode and proposes to establish management control mode where application and of rod pumped well engineering design system software is organically linked with maintenance from the perspective of the user.

In view of the specialty of the salt formation, a kind stabilizing method which consists of a protecting wall mud system and a casing & cementing technique had been presented in the paper. According to the actual situation of brine well construction, well structure, drilling fluid type, casing program and cement formula have been optimized. Scientifically using the drilling fluid system and the technology of casing cementing, the down well incidents such as wall collapse, leakage, overgauge well, water sensitivity denudation and sand contamination could be effectively avoided, and the drilling process and well's quality should be ensured.

Master's thesis in Petroleum engineering Energy industries have been taking advantages from the recent developments of nanotechnology. Several revolutionary changes can be made in drilling industry with the help of nanotechnology. It has a capability to produce such nanomaterials that can bring benefit to the industry in various manners such as improving the quality of mud cake, decreasing the frictional resistance in the well, minimizing the risk of pipe sticking, establishing borehole stability, preventing reservoir from formation damage, and augmenting the recovery of oil and gas. In the field of drilling fluids, researchers have tested the application of nanoparticles and have concluded with very promising results in terms of reduction in torque and drag, stabilizing the well bore, controlling fluid loss and improving hole cleaning efficiency. Use of the nanoparticles in reducing friction and improving lubrication effect has already been recognized in different industries. Drilling industry has moved towards exploiting reservoir in more economical ways such as drilling an extended reach well. These wells are quite challenging when it comes to solving down hole drilling problems such as high torque and drag. Lubrication efficiency of drilling fluids can play a decisive role in solving torque and drag problem. Although oil based drilling fluid offers reduced friction factor in the wellbore, environmental concerns and high expenditures can limit its usage. An alternate solution is to make the most of better lubrication efficiency of the nanoparticles by adding them in drilling fluid particularly to water base drilling fluids. This addition also has its impact on the rheological properties of drilling fluid which can affect its other function. By keeping this agenda in mind, different nanoparticles were added to drilling fluids at different concentrations and the impact on friction factor and viscosity was studied through tribometer and rheometer respectively. Graphene, carbon nanotubes, silica, alumina, cobalt and nickel nanoparticles were selected as potential particles and their effects were studied in three different base fluids. Temperature influence on tribology and rheology were also made part of the study. The reliability of test results was established by using Modular Compact Rheometer (MCR) for rheological measurements and Pin-on-Disc Tribometer for friction factor measurements. In addition to this, the impact of nanoparticles’ addition on density and pH of drilling fluid was also evaluated and the results were used to ponder on the relationship between different properties of drilling fluid. Evaluation of viscosity and friction factor led to selection of the best nano drilling fluids which were further used in case study to develop temperature, viscosity, friction factor and torque and drag profile using software technology. The comparison of results between conventional drilling fluid and nano drilling fluids proves that nano drilling fluid can deliver better performance in terms of better bit cooling, enhanced viscous behavior, low friction factors, and reduced torque and drag.

Master's thesis in Petroleum engineering Increasing temperature and pressure with depth, affects the properties of drilling fluid. The effect of temperature and pressure on the density and viscosity of drilling fluid is of great importance. This is because, among several reasons, it affects the calculation of downhole pressure and the buoyancy factor for the well. Correct pressure estimation, could pose a great concern regarding well integrity. The buoyancy factor would affect the effective weight of the drillstring, which again would be a property of calculation of torque and drag force in a well. In the work of evaluating the downhole temperature and pressure, modelling is important. In this thesis, models to do so, is investigated. Simulation of downhole conditions have been carried out. Sensitivity analysis, regarding the most critical parameters of the temperature, is performed. The effect of different sized pipes and equipment’s on the temperature and pressure will be investigated. If the result of changed size of a pipe is higher or lower temperature and/or pressure, this would again affect the density and viscosity of drilling fluid. Torque and drag force is, as mentioned, connected to the calculation of the buoyancy factor. Torque and drag control is an important aspect of well design. In order to be able to drill as far as desired, drag force and torque loss needs to be properly handled. In the evaluation of torque and drag force, it is differentiated between straight inclined wellbore and curved wellbore. Conditions for determining whether the wellbore is either straight inclined or curved, will be implemented in the torque and drag force calculations. In addition, the effect of combined motion on the torque and drag force, will be investigated. Findings regarding the combined motion, indicates that torque and drag force is affected by combined motion. Regarding the drag force, it is observed, that generally, the drag force is lower for the cases with constant buoyancy factor throughout the well, than for the cases with varying buoyancy factor with depth. For the torque, it was observed, that generally, the torque for cases including lowering, hoisting and static conditions of the drillstring, the torque in the well is lowered when a constant buoyancy factor is applied.

Master's thesis in Petroleum engineering Managed Pressure Drilling (MPD) is a drilling technology that has been developed to manage and control the downhole pressure in the well in order to minimize drilling-related problems. This technology uses a pressurized closed-loop system and specialized equipment that allows better and more accurate pressure control of downhole pressure profile, therefore avoids drilling problems associated with downhole pressure variations, optimizes the drilling process by minimizing the non-productive time (NPT) and enables drilling prospects that are technically and/or economically un-drillable with conventional drilling methods. An essential part of Managed Pressure Drilling operation is the control of the downhole pressure and it can be a challenging task due to the complex dynamics of wellbore hydraulics. In order to estimate the downhole pressure profile, a simplified hydraulic model has been recognized as a more convenient alternative than advanced hydraulic model since in the most cases, the available data contain insufficient information and several parameters are both uncertain and slowly changing that leads to higher level of complexity for the advanced hydraulic model. By using simplified hydraulic model and available measurements, the pressure and flow dynamics of the well can be estimated. However, the downhole measurement is less reliable than the topside measurement because of slow sampling, and loss of communication for low or no-flow conditions, e.g., during pipe connection procedures. Depending just on the topside measurement, the downhole pressure needs to be accurately estimated despite the uncertainties in parameters such as friction, density, fluid loss etc. This Master Thesis work describes an adaptive observer design to estimate the system states and the unknown parameter for the hydraulics of Managed Pressure Drilling using only one boundary measurement at the topside. Numerical simulations are performed to demonstrate the effectiveness of the adaptive observer. The results from simulations of drilling events such as drilling connection and lost circulation and also analysis from Lyapunov approach shows that the estimation error converges to zero, and the downhole pressure, the flow dynamics, the rate of lost circulation and other unknown parameters can be accurately estimated.

Recognised as the first high pressure and high temperature (HPHT) development ever embarked by PETRONAS as well as the first of its kind in Malaysia, KN-UUD Development had also marked a significant step change in well engineering design approach for Asia Pacific region. Learning from experience of HPHT operators in the North Sea and the Gulf of Mexico, a detailed focus on lifecycle well integrity aspect had been thoroughly emphasised throughout the well design phase. Innovative design thoughts, meticulous process in selecting cost effective solutions and strong collaboration between operator and service providers proved to be the key ingredients for success. This paper highlights the sophisticated journey of KN-UUD HPHT development well delivery, covering the initial scoping work, design phase, equipment (and material) planning and testing, execution phase as well as the lessons learnt from the campaign. Challenges and experiences discussed include: Depletion on shallow reservoirs, its impact towards pore pressure and fracture gradient profile and subsequently, overall well design. First implementation of big bore well design with liner and cemented tieback philosophy in Asia Pacific. HPHT lifecycle integrity aspect and considerations on worst case scenario i.e. reservoir compaction study, cement stress analysis, tubular connection and material testing. Challenges in dealing with non-availability of equipment (including material) and lack of service capability within the region. Complex process of identifying and procuring fit-for-purpose equipment solutions and unique contracting strategy. Annulus management philosophy for HPHT development. Lessons learnt from the actual well construction phase. The well was successfully delivered to meet all of its objectives, producing from layers close to 16,000 ft. beneath the seabed. The complex process, obstacles and vital experience in overcoming the challenges has pioneered a path for future application of its kind within Malaysia and Asia Pacific region.